Anaerobic fermentation of biological waste materials produces methane, together with carbon dioxide and, frequently, significant quantities of hydrogen sulfide (H2S) plus traces of other volatile sulfur containing compounds. This anaerobic fermentation may occur in waste processing, such as sewage treatment and wastewater treatment plants or in sewers. It also can be produced in landfills and anaerobic fermenters used for biogas production. Landfills and anaerobic fermenters produce methane that may be used for bioenergy production. Typical compositions of gases from either landfills (composition varies markedly depending on the materials in the landfill) or from anaerobic fermentation of materials, such as farm manure, typically contain 40-60% methane (CH4), similar levels of carbon dioxide (CO2), some other gases such as carbon monoxide, and varying levels of H2S, ranging from a low level to 10-30,000 ppm. The contamination of biogas with corrosive and toxic H2S limits its use. Use of gases that contain hydrogen sulfide at concentrations over 200 ppmv will void turbine manufacturers' warranties, and many municipalities or other governmental agencies limit the amount of H2S that can be present to as low as 3 ppmv. On-farm electrical energy from digester biogas occurs now with internal combustion engines; the corrosive characteristics are mitigated by frequent oil changes. However, combustion of the gas results in production of the air pollutant SO2 at levels roughly equimolar to the amount of H2S in the input gas. Wide-scale use of any biogas will necessitate avoidance of release of sulfur compounds into the atmosphere.
Hydrogen sulfide is toxic, has an unpleasant smell, and is highly corrosive. Hydrogen sulfide gas is explosive when mixed with air at 4.5 to 45.5% (www.OSHA.gov). The LD50 for inhalation (rat) is 444 ppm (physchem.ox.ac.uk/MSDS/HY/hydrogen_sulfide.html). Clearly, methods for economical removal of H2S from biogas are required if sulfur-containing biogases are to be used for large-scale energy production.
Hydrogen sulfide and other reduced sulfur compounds may be present at high concentrations in landfill gases that are produced from sites that contain high levels of construction and demolition debris. These compounds result from microbial activity on gypsum present in drywall, where the sulfates in the gypsum are reduced to hydrogen sulfide and other reduced volatile sulfur compounds (Lee, S., Q. Xu et al., “Reduced Sulfur Compounds in Gas from Construction and Demolition Debris Landfills,” Waste Manage. 26:526-533 (2006)). Some sites operated have concentrations in landfill gases at levels of 10,000 ppmv H2S and 1200-1500 scfm gas flows. Other sites produce landfill gas containing 500-700 ppmv of H2S at 200-300 scfm. Thus, many landfill gas sites produce hydrogen sulfide at concentrations that are too high to allow for bioenergy production.
Anaerobic digesters used for on-farm manure disposal are an important underutilized resource for energy production, although use is increasing. Between 1991 and 2002 the number of units either planned or in operation has increased nationwide from about 20 to more than 80 (www.cogeneration.net/anaerobic_digesters.htm). However, in 1995, a study estimated that 3000 to 5000 systems could be economically installed in the USA (referenced in Zicari, S. M., “Removal of Hydrogen Sulfide from Biogas Using Cow-Manure Compost,” Animal Science, Thesis, Cornell University, Ithaca, N.Y., 120 pages (2003)). Generally, at least 500 cows are required to create a sufficiently large level of biomass for economical biogas production. According to one estimate, if all of the dairy manure in New York State was anaerobically digested, the annual energy potential would be 280 GWh, which would support the energy demands of 47,000 households as well as providing all of the energy demands for the producing farms (Ma, J., “Spatial Analysis of the Potential for Dairy Manure as a Renewable Energy Resource in New York State,” Animal Science, Cornell University, Ithaca, N.Y., 108 (2002)). In addition, these systems are important components of total manure management strategies. The biogas produced by anaerobic digesters is typically 50-80% methane with the remainder being CO2, and there is typically about 4000 ppmv of H2S in the gas mixture (Zicari 2003), although levels in some tests were as high as 30,000 ppm in a recently restarted fermenter.
In addition to bioenergy production systems, copious amounts of the gas are produced by sewage treatment and waste water treatment plants. H2S must be removed from these gas streams to avoid nuisance and toxic odors. In addition, if the gas is flared without H2S removal, SO2 will be formed and this results in air pollution and acid rain.
H2S is also produced as a bioproduct of various industrial processes. In these processes, other materials are produced along with H2S. These materials include, for example, other reduced sulfur compounds such as mercaptans. Industries where H2S and other reduced sulfur compounds are produced include, but are not limited to, the petroleum extraction and refining processes, food processing where sulfur compounds are used, and in odor nuisance abatement of all sorts, including farm operations. Therefore, there is a need for methods and compositions for the removal of H2S and other reduced sulfur compounds from gaseous mixtures as well as liquid mixtures (e.g., water containing H2S or other reduced sulfur compounds).
There are several types of systems for removal of H2S from gas streams. Many of them use iron as the active ingredient. The difference between them is the delivery system, and this may dramatically affect both ease of operation and expense. Such systems are based on several chemical reactions, as follows:
1. Fe+2+H2S→FeS+2 H+
2. Fe2O3.H2O+3 H2S→Fe2S3+4 H2O
3. Fe2S3+3O2+2 H2O→Fe2O3.H20+6S
(regeneration of matrix using oxygen)
These few reactions appear rather simple. However, making commercially useful systems based upon these reactions may be complex, given the fact that iron, unless chelated to expensive and somewhat labile organic molecules, precipitates from solution at pH levels above 1.5-2.0, depending on the concentration. Most processes, other than those using chelated iron, use ferrous or ferric hydroxide, which forms a slimy precipitate that makes its use difficult. Some of the older materials (e.g. IRON SPONGE, Connelly-GPM, Inc., Chicago, Ill.) may combust spontaneously if on an organic surface. To avoid such difficulties, materials such as SULFATREAT (SulfaTreat, a business unit of M-I, LLC, Chesterfield, Mo.) come already processed on a ceramic base. Thus, the material must be produced in a factory, dried, and then shipped. The solid matrices such as iron sponge and SULFATREAT are usually more economical for smaller facilities, while more complex systems involving chelated iron may be more suited to larger users. However, even IRON SPONGE and SULFATREAT may not be economical for many applications.
IRON SPONGE is an old technology (used for more than 100 years). It uses ferric oxide or hydroxide coated onto wood chips. In particular, the iron is coated onto the surface of platelets of bark or wood (e.g., about ⅛×3×1 inches). The chips are loaded into columns or silos, then the moist biogas is passed through and H2S is efficiently removed. One major disadvantage of this system is that Reaction 3 (above) is exothermic and when the products from Reaction 2 (above) are exposed to air, spontaneous combustion may occur. Service providers to safely handle this issue are required and so the system may not be particularly well suited to small scale operations, such as dairy farms (see www.marcabcoinc.com/article.htm). However, currently, it probably is the simplest and least expensive system to operate. One factor limiting its usefulness is the fact that the number of regeneration cycles using Reaction 3 (above) is limited usually to about three (www.marcabcoinc.com/page4.html), and even with these few cycles, efficiency is reduced. Clearly, a system that can be regenerated without loss of efficacy many more times would be much more cost-effective. IRON SPONGE has an advantage over some other systems, in that there is a small pressure drop in the filtering medium.
SULFATREAT, SULFUR-RITE® (Merichem, Schaumburg, Ill.), and related systems are basically the IRON SPONGE systems, but with the iron hydroxides coated onto diatomaceous earth or similar materials. This eliminates the pyrogenic problems. SULFATREAT has been used to treat more than 1 trillion cubic feet of gas annually (Braga, T. G., octane.nmt.edu/sw-pttc/proceedings/H2S—05/Sulfatreat.pdf). It passes all environmental tests, is nontoxic, and has shown good results when used as a plant fertilizer. One version of the process is described in detail in U.S. Pat. No. 6,500,237. There are various versions of the process, including recovery of free sulfur (Reaction 3) in the molten form (see www.hydrocarbonengineering.com/Hydrocarbon/he_sulfur_sulfa.htm, www.tda.com/Library/docs/SulfaTreat%20rev%20-DO_V2a.pdf).
One disadvantage to SULFATREAT and related systems is that relatively high pressure must be used to force gas through the systems and so the initial costs are increased due to the requirement for high pressure vessels. Both the SULFATREAT and IRON SPONGE systems are produced at central locations, which requires expensive shipment.
LO-CAT® (Merichem, Schaumburg, Ill.) and its related systems use the same basic iron chemistry as SULFATREAT. However, its innovation is the use of an iron chelate to keep the iron in solution. These liquid systems generally consist of two vessels. In the first vessel is a solution containing chelated ferric compounds where sulfur is trapped (Reaction 2), and where the iron oxidizes the H2S to elemental sulfur and ferrous iron. The solution containing the ferrous iron is then pumped to a second tank where oxygen is introduced to convert the ferrous to ferric iron to regenerate the system. This system is not well suited to smaller scale operations (Heguy and Nagel, at www.gtp-merichem.com/support/technical_papers/state_of_iron_redox.php). The systems require extensive monitoring and evaluation.
Hydrogen sulfide removal systems not using iron as the absorptive ion also exist (see, e.g., U.S. Pat. Nos. 6,500,237; 6,544,492; 6,551,570; 7,004,996; and 7,427,383).
There is a need for an improved and less expensive method for removing hydrogen sulfide and other reduced sulfur compounds from gaseous and liquid mixtures. There is a particular need for a regenerable sulfur removal system that is cost effective, efficient, and able to be used on-site (e.g., in biomethane production from anaerobic digesters, landfills, water treatment and processing plants, the petroleum industry, dairy farms, and others).
The present invention is directed to overcoming these and other deficiencies in the art.